Fault Seal Analysis: Methodology and Case Studies

M. E. Badley, B. Freeman, D. T. Needham, and G. Yielding

Fault seal can arise from reservoir/non-reservoir juxtaposition or by development of fault rock of high entry-pressure. The methodology for evaluating these possibilities uses detailed seismic mapping and well analysis.

A 'first-order' seal analysis involves identifying reservoir juxtaposition areas over the fault surface, using the mapped horizons and a refined reservoir stratigraphy defined by isochores at the fault surface.

The 'second-order' phase of the analysis assesses whether the sand-sand contacts are likely to support a pressure difference. We define two lithology-dependent attributes: 'Gouge Ratio' and 'Smear Factor'. Gouge Ratio is an estimate of the proportion of fine-grained material entrained into the fault gouge from the wall rocks. Smear Factor methods estimate the profile thickness of a ductile shale drawn along the fault zone during faulting. Both of these parameters vary over the fault surface implying that faults cannot simply be designated 'sealing' or 'non-sealing'.

An important step in using these parameters is to calibrate them in areas where across-fault pressure differences are explicitly known from wells on both sides of a fault. Our calibration for a number of datasets shows remarkably consistent results despite their diverse settings (e.g. Brent Province, Niger Delta, Columbus Basin). For example, a Shale Gouge Ratio of c. 20% (volume of shale in the slipped interval) is a typical theshold between minimal across-fault pressure difference and significant seal.

AAPG Search and Discover Article #91019©1996 AAPG Convention and Exhibition 19-22 May 1996, San Diego, California